This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for numerous years. To produce these hydrocarbons, a production system may utilize various devices, such as sand screens and other tools, for specific tasks within a well. Typically, these devices are placed into a wellbore completed in either cased-hole or open-hole completion. In cased-hole completions, wellbore casing is placed in the wellbore and perforations are made through the casing into subterranean formations to provide a flow path for formation fluids, such as hydrocarbons, into the wellbore. Alternatively, in open-hole completions, a production string is positioned inside the wellbore without wellbore casing. The formation fluids flow through the annulus between the subsurface formation and the production string to enter the production string.
However, when producing hydrocarbons from subterranean formations, it becomes more challenging because of the location of certain subterranean formations. For example, some subterranean formations are located in ultra-deep water, at depths that extend the reach of drilling operations, in high pressure/temperature reservoirs, in long intervals, at high production rate, and at remote locations. As such, the location of the subterranean formation may present problems that increase the individual well cost dramatically. That is, the cost of accessing the subterranean formation may result in fewer wells being completed for an economical field development. Accordingly, well reliability and longevity become design considerations to avoid undesired production loss and expensive intervention or workovers for these wells.
As an example, when producing formation fluids from subterranean formations located in deep water, it is possible to produce solid material, such as sand, along with the formation fluids because the formations are poorly consolidated or the formations are weakened by downhole stress due to wellbore excavation and formation fluid withdrawal. Sand control devices are usually installed downhole across these formations to retain solid material, but allow fluids to be produced. Loss of sand control may result in sand production at the surface, downhole equipment damage, reduced well productivity and/or loss of the well. Under the increasingly harsh environments, sand control devices are more susceptible to damage due to high stress, erosion, plugging, compaction/subsidence, etc. Such damage may occur to the sand control devices during transportation, installation, completion, injection, production, or stimulation. In fact, damage to the sand control devices is difficult to predict or prevent. As a result, sand control devices are generally utilized with other methods to manage the production of sand from the subterranean formation.
One of the most commonly used methods to control sand is a gravel pack. Gravel packing a well involves placing gravel or other particulate matter around a sand control device that is coupled to the production string. The sand control device may have openings or may be wrapped by a screen. For instance, in an open-hole completion, a gravel pack is typically positioned between the wall of the wellbore and a screen that surrounds a perforated base pipe. Alternatively, in a cased-hole completion, a gravel pack is positioned between a casing string having perforations and a well screen that surrounds a perforated base pipe. Regardless of the completion type, formation fluids flow from the subterranean formation into the production string through the gravel pack and sand control device.
Other sand control methods utilize may include standalone screens and frac packs to address the sand production problem. Recent technology advance in sand control has been focused on monitoring downhole conditions, improving sand retention, increasing flow performance, and reducing erosion potential. For instance, screens may be designed to enhance sand retention efficiency and flow performance. Similarly, the openings in screens may be adjusted to reduce erosion. Also, sensors may be installed in hollow wires or rods in a sand screen to monitor pressure, temperature, density, etc. to provide information about sand control performance.
Currently, sand control equipment includes little, if any, redundancy that addresses problems with failures resulting in flow impairment. In many instances, the ability of a well to produce at or near its design capacity is sustained by only a “single” barrier to the impairment mechanism. That is, a sand screen may be the only device that is utilized to control sand in unconsolidated formations. As a result, any damage to the installed sand screen may result in the production of sand along with the hydrocarbons. If a gravel pack is installed, screen damage may cause both gravel and sand production. Solids production may result in downhole equipment erosion, productivity impairment, sand handling challenges at the surface, and/or partial or complete loss of well productivity. As a result, workovers or sidetracks are eventually required. Thus, the overall system reliability for well completions has great uncertainty.
Accordingly, the need exists for a more reliable well completion apparatus and method to provide redundancy for screens, alternative flow paths inside the screens, and self-mitigating functionality, which includes compartmentalization to address the uncertainty in mechanical damage of sand control screen.
Other related material may be found in at least U.S. Pat. No. 4,945,991; U.S. Pat. No. 5,095,990; U.S. Pat. No. 5,113,935; U.S. Pat. No. 5,293,935; U.S. Pat. No. 5,476,588; U.S. Pat. No. 5,515,915; U.S. Pat. No. 5,642,781; U.S. Pat. No. 5,642,781; U.S. Pat. No. 5,938,925; U.S. Pat. No. 6,125,932; U.S. Pat. No. 6,227,303; U.S. Pat. No. 6,554,064; U.S. Pat. No. 6,684,951; U.S. Pat. No. 6,715,544; U.S. Pat. No. 6,745,843; and U.S. Patent Application Publication No. 2005/0034860.